GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 

# Final Report



# BART Analysis for

Healy Power Plant

Prepared For: 

# Golden Valley Electric Association

Fairbanks, Alaska



### January 2009

Prepared By:GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-1 

# Executive Summary

Background
In response to the Regional Haze Rule and Best Available Retrofit Technology (BART) regulations and guidelines, CH2M HILL was requested to perform a BART analysis for Golden Valley Electric Association, Inc. (G VEA) Healy Power Plant. Unit 1 (hereafter referred to as Healy 1) and Auxiliary Boile r #1 are considered BART sources. The Alaska Department of Conservation (A DEC) has determined that the GVEA Healy Power Plant is subject to BART evaluation becaus e it was built in the time period covered by the rule (1962-1977) and has been shown through modeling to have a greater than 0.5 deciview (dV) visibility impact at Denali National Park and Preserve (DNPP), a federal Class I area. ADEC determined that oxides of nitrogen (NO x ) emissions were the primary contributor to visibility impairment; howeve r, BART analyses for sulfur dioxide (SO 2 ) and particulate matter (PM) were also required by the agency. For Healy Unit 1, a BART analysis has been co nducted for the following criteria pollutants: NO x , SO 2 , and particulate matter less than 10 microns in aerodynamic diameter (PM 10 ). For Auxiliary Boiler #1, there were essentially no visibility impacts, and no controls analysis was conducted. The U. S. Environmental Protection Agency (EPA) BART guidelines provide presumptive BART emission limits whereas units emitting at or below the presumptive limits are considered to meet BART. These presumptive le vels, however, are typically applicable to large units over 200 megawatts (MW) at 7 50-MW facilities., Since presumptive BART limits have not been prescribed for extremel y small units such as Healy, however, the presumptive BART limits found in the BART gu idelines have been used as a general guide in evaluating potential control options. BART emissions limits must be achieved within 5 years after the State Implementation Plan (SIP ) is approved by the EPA, and a compliance date of 2014 was assumed for this analysis. Healy Unit 1 is a 25-MW boiler equipped with pollutant controls for NO x , SO 2 and PM10. Controls currently in place include low NO x burners (LNB) with over fire air (OFA), dry sorbent flue gas desulfurization (FGD) and a baghouse. In completing the BART analysis, technology al ternatives were investigated, and potential reductions in NO x , SO 2 , and PM 10 emissions were evaluated. The following technology alternatives were investigated as improvements to reduce emissions and are listed below by pollutant:

NO x emission controls:

• Maintain current operation and utilize existing LNB with OFA

• Optimize existing LNB with OFA through the utilization of a boiler consultantBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-2 • Replace OFA with Rotating opposed fire air (ROFA)

• Replace OFA with ROFA and Rotomix

• Add selective non-catalytic reduction (SNCR) system to existing low NO x burners with OFA

• Add selective catalytic reduction (SCR) system to existing low NO x burners with OFA

SO 2 emission controls:

• Maintain current operation and utilize existi ng sodium bicarbonate injection system

• Increase sodium bicarbonate injection rate to improve SO2 removal utilizing the existing sorbent injection system

• Install lime spray dryer FGD system

• Install wet limestone FGD system

PM 10 emission controls: Since fabric filter technology is considered to be BART, no alternative PM 10 technologies were considered. 

# BART Engineering Analysis
The specific steps in a BART engine ering analysis are identified in the Code of Federal Regulations (CFR) at 40 CFR 51 Appendix Y, Section IV. The evaluation must include the following:

1. The identification of available, techni cally feasible, retrofit control options

2. Consideration of any pollution control equipment in use at the source (which affects the availability of options and their impacts)

3. The costs of compliance with the control options

4. The remaining useful life of the facility

5. The energy and non-air quality environmental impacts of compliance
6. The degree of visibility improvement which ma y reasonably be anticipated from the use of BART
These steps are incorporated into the BART analysis as follows: Step 1 – Identify All Available Retrofit Control Technologies

• This engineering analysis evaluates control options and discusses control technologies for Healy Unit 1. Step 2 – Eliminate Technically Infeasible Options

• The identification of available, techni cally feasible, retrofit control options

• Available space was not a consideration in determining feasibilityBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-3 • Consideration of any pollution control equipment in use at the source (which affects the applicability of options and their impacts) Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies Step 4 – Evaluate Impacts and Document the Results

• The costs of compliance with the control options

• The remaining useful life of the facility

• The energy and non-air quality environmental impacts of compliance Step 5 – Evaluate Visibility Impacts

• The degree of visibility improvement which ma y reasonably be anticipated from the use of BART Separate analyses have been conducted for NO x , SO 2 , and PM 10 emissions. All costs included in the BART analyses are in 2008 dollars, and costs have not been escalated to the assumed 2014 BART implementation date.


# Coal Characteristics
The only source of coal burned at Healy Unit 1 is low-sulfur sub-bituminous coal from the Usibelli Mine (UCM). 

# BART Modeling Analysis
The CALPUFF Gaussian puff disp ersion modeling system to assess the visibility impacts of emissions from Healy 1 and Auxiliary Boiler # 1 on DNPP, which is a Class I area. Twenty four hour average actual emissions rate from the highest emitting day in the one year period from May 1, 2007 to April 30, 2008 were comp ared to current anticipated emission rates and those of evaluated control technologies. DNPP is located approximately 8 kilometers (5 miles) from the Healy Power Plant. Visibility improvements for all of the emissi on control technologies listed above were analyzed, and the results were compared utilizing a Least-Cost Envelope, as outlined in the draft EPA 1990 New Source Review Workshop Manual and referenced in the EPA BART guidelines. 

# Least-Cost Envelope Analysis
EPA typically uses the Least-Cost Envelo pe Analysis Methodology as an accepted methodology for selecting the most reasonable , cost-effective controls. Incremental costeffectiveness comparisons focus on annualized cost and emission reduction differences between dominant alternatives. The dominant set of control alternatives is determined by generating what is called the envelope of least- cost alternatives. This is a graphical plot of total annualized costs for a total emissions reduct ions for all control alternatives identified in the BART analysis.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-4 To evaluate the impacts of the modeled control options on DNPP, the total annualized cost, cost per dV reduction, and cost per reduct ion in number of days above 0.5 dV were analyzed. This report provides a comparison of the average incremental costs between relevant control options for Healy 1; the total annualized cost versus number of days above 0.5 dV, and the total annualized cost versus delta-deciview ( ∆ dV) reduction. 

# Just-Noticeable Differences in Atmospheric Haze

Studies have been conducted that demonstrate on ly dV differences of approximately 1.5 to 2.0 dV or more are perceptible by the human eye. Deciview changes of less than 1.5 cannot be distinguished by the average person. Ther efore, the modeling analysis results indicate that based on the above, no observable visibi lity improvements at DNPP would be expected under any of the control options. 

# BART Technologies The following summarizes the BART analysis for the Healy Power Plant



## NOx Emission Control Although Healy 1 has visibility impacts that exceed the 0.5 dV threshold defined in the BART rules as requiring evaluation of contro ls, this analysis shows applicable NOx BART controls to have no observable improvement to visibility. Therefore, the current plant controls for NOx are considered BART. Emissions and impacts from Auxiliary Boile r #1 are insignificant; therefore, no NO x control improvements are recommended for this unit.



## SO 2 

## Emission Control Although Healy 1 has visibility impacts that exceed the 0.5 dV threshold defined in the BART rules as requiring evaluation of co ntrols, this analysis shows applicable SO 2 BART controls to have no observable improvement to visibility. Therefore, the current plant controls for SO 2 are considered BART. Emissions and impacts from Auxiliary Boiler #1 are insignificant, and no SO 2 controls are concluded as BART for this unit.



## PM 10



## Emission Control The existing fabric filter is concluded to be BART for Healy 1 since it is the best technology available for PM 10 control. Emissions and impacts from Auxiliary Boiler #1 are insignificant, and no PM 10 controls are concluded as BART for this unit. 

# Recommendations It is recommended that the existing controls for all pollutants constitute BART. While technologies presented in this report have b een shown to reduce emissions of visibility impairing pollutants, it is recommended that the no additional control technologies beBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-5 implemented. From previous visibility studies that have been completed, it was concluded that visibility impairment at DNPP from He aly has not been obse rved by trained NPS observers. Also, there is little visibility benefit projected with expected emission improvement from the evaluated BART technologies. In addition, there may be unintended consequences of implementing the BART controls. Optimizing the existing low NO x burners (LNB) with over-fire air (LNB w/OFA) will result in an increase of CO emissions. Increasing the sodium bicarbonate injection rate has been shown in preliminary testing to increase emission of mercury. Consequently the undetect able slight potential decrease in visibility impairment does not warrant the increase in other pollutants.GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ii 

# Contents

Section Page Executive Summary.............................................................................................................. ........ES-1 Background ..................................................................................................................... .. ES-1 BART Engineering Analysis ........................................................................................... ES-2 Coal Characteristics.......................................................................................................... E S-3 BART Modeling Analysis................................................................................................ ES-3 Least-Cost Envelope Analysis ........................................................................................ ES-3 Just-Noticeable Differences in Atmospheric Haze ...................................................... ES-4 BART Techno logies.......................................................................................................... ES-4 NOx Emission Control........................................................................................ ES-4 SO 2 Emission Control.......................................................................................... ES-4 PM 10 Emission Control ....................................................................................... ES-4 Recommendations............................................................................................................ ES-4 1.0 Introduction................................................................................................................... ......1-1 2.0 Present Unit Operation......................................................................................................2-1 3.0 BART Engineering Analysis ............................................................................................3-1 3.1



### .... Applicability...............................................................................................................3-1 3.2



### .... BART Process .............................................................................................................3-1 3.2.1 BART NO x Analysis ..................................................................................3-2 3.2.2 BART SO 2 Analysis .................................................................................3-10 3.2.3 BART PM 10 Analysis ...............................................................................3-15 4.0 BART Modeling Analysis.................................................................................................4-1 4.1



### .... Model Selection..........................................................................................................4-1 4.2



### .... CALMET Methodology ............................................................................................4-1 4.2.1 Dimensions of the Modeling Domain ....................................................4-1 4.3



### .... CALPUFF Modeling Approach...............................................................................4-4 4.3.1 Background Ozone and Ammonia .........................................................4-4 4.3.2 Stack Parameters........................................................................................4-4 4.3.3 Emission Rates ...........................................................................................4-5 4.3.4 Individual Contro l Scenarios...................................................................4-5 4.3.5 Modeling Process ......................................................................................4-9 4.3.6 Receptor Grids ...........................................................................................4-9 4.4



### .... CALPOST....................................................................................................................4-9 4.5



### .... Presentation of Modeling Results..........................................................................4-10 4.5.1 Degree of Visibility Change for Ba seline vs. Preferred Scenario......4-10 5.0 Preliminary Assessment and Recommendations.........................................................5-1 5.1



### .... Least-Cost Envelope Analysis..................................................................................5-1 5.1.1 Analysis Methodology..............................................................................5-2 5.1.2 Analysis of Results ....................................................................................5-9 5.2



### .... BART Conclusions.....................................................................................................5-9 5.2.1 NO x Emission Control ..............................................................................5-9 5.2.2 SO 2 Emission Control................................................................................5-9CONTENTS (CONTINUED)

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC iii 5.2.3 PM 10 Emission Control .............................................................................5-9 5.2.4 Auxiliary Boiler # 1 ...................................................................................5-9 5.3



### .... Just-Noticeable Difference in Atmospheric Haze .................................................5-9 5.4



### .... Recommendations ...................................................................................................5-10 6.0 References..................................................................................................................... .......6-1



## Tables
Table 2-1 Present Unit Operation .............................................................................................2- 1 Table 3-1 NOx Control Technology Emission Rates..............................................................3-4 Table 3-2 NOx Control Cost Comparison ...............................................................................3-8 Table 3-3 Summary of SO2 Control Effectiveness................................................................3-12 Table 3-4 SO2 Control Cost ..................................................................................................... 3-14 Table 4-1 User-Specified CALMET Options ...........................................................................4-3 Table 4-2 CALMET Surface Stations........................................................................................4-4 Table 4-3 BART Model Input Data...........................................................................................4-6 Table 4-4 Stack Parameters and Emission Rates Healy Unit1..............................................4-7 Table 4-5 Stack Parameters and Emission Rates Auxiliary Boiler #1..................................4-8 TAble 4-6 Average Natural Levels of Aerosol Components ...............................................4-10 Table 4-7 Costs and Visibility Modeling Results for Baseline vs. Individual Control Scenarios.....................................................................................................4-11 Table 4-8 Visibility Results for Auxiliary Boiler #1 .............................................................4-11 Table 5-1 Class I Area Summary of Control Performance ....................................................5-2 Table 5-2 Class I Area Incremental Data .................................................................................5-4 Table 5-3 Annual Cost and Tons Removed Based on Current Operating Values.............5-7



## Figures Figure 3-1 First Year Control Cost for NOx Air Pollution Control Options ........................3-9 Figure 3-2 First Year Control Cost for SO2 Air Pollution Control Options .......................3-15 Figure 4-1 Healy BART Modeling Domain ..............................................................................4-2 Figure 5-1 Least Cost Envelope Compared to Baseline ..........................................................5-5 Figure 5-2 Least Cost Envelope Compared to Baseline ..........................................................5-5 Figure 5-3 Least Cost Envelope Compared to Baseline ..........................................................5-6 Figure 5-4 Least Cost Envelope Compared to Baseline ..........................................................5-6 Figure 5-5 Additional Annual cost versus Additio nal Tons Removed Compared to Existing Operations ...................................................................................................5-8 Figure 5-6 Additional Annual cost versus Additio nal Tons Removed Compared to Existing Operations ...................................................................................................5-8 

## Appendix A Economic AnalysisGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC iv 

# Acronyms and Abbreviations

ADEC Alaska Department of Conservation

∆ dV delta deciview, change in deciview °F degree Fahrenheit ADEC Alaska Department of Environmental Conservation BACT Best Available Control Technology BART Best Available Retrofit Technology
BTU British Thermal Unit CALMET Meteorological data pr eprocessing program for CALPUFF CALPOST Post-processing program fo r calculating visibility impacts CALPUFF Gaussian puff dispersion model

CEM Continuous Emissions Monitor CFR Code of Federal Regulations
DNPP Denali National Park and Preserve
dV deciview EPA United States Environmental Protection Agency FGD flue gas desulfurization GVEA Golden Valley Electric Association, Inc. HCCP Healy Clean Coal Project Healy 1 Healy Power Plant Unit 1 hp horsepower
km kilometer
kW kilowatt
kWh kilowatt-hour
LAER lowest achievable emission rate lb pound
LNB Low-NO x burner LOI loss on ignition MM5 Mesoscale Meteorological Model, Version 5
MMBtu Million British thermal units MW megawattsACRONYMS (CONTINUED)

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC v N 2 nitrogen
NO nitric oxide

NO x nitrogen oxides
NPS National Park Service
OFA over fire air

PM 10 particulate matter less than 10 microns in aerodynamic diameter PSD prevention of significant deterioration RMC Regional Modeling Center ROFA Rotating Opposed Fire Air SCR selective catalytic reduction system SIP State Implementation Plan SNCR selective non-catalytic reduction system

SO 2 sulfur dioxide
UCM Usibelli Coal Mine WRAP Western Regional Air PartnershipGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 1-1 

# 1.0 Introduction

Best Available Retrofit Technology (BART) gu idelines (40 Code of Federal Regulations [CFR] Part 51) were established as a result of United States Environmental Protection Agency (EPA) regulations intended to reduce the occurrence of regional haze in national parks and other Class I protected air quality ar eas in the United States. These guidelines provide guidance for states when determinin g which facilities must install additional controls, and the type of controls that must be used. Facilities subject to BART controls were built between 1962 and 1977 and have the potential to emit more than 250 tons/year of visibility-impairing pollutants. The Alaska Department of Environmenta l Conservation (ADEC) has identified those eligible in-state facilities that are required to evaluate emissions under BART. The list includes the Golden Valley Electric Association, Inc. (GVEA) Power Plant Unit 1 (Healy 1) and Auxiliary Boiler #1. As a BART subject source, GVEA was required to submit a BART analysis, for the Healy Po wer Plant to ADEC by July 28, 2008. GVEA has addressed visibility impacts previously and has significant data worthy of consideration. GVEA received a Prevention of Significant Deterioration (PSD) construction permit and Permit to Operate No. 9431-AA001 from the ADEC in 1994 for operations at the Healy power plant when those operations were expanded to include the Healy Clean Coal Project (HCCP), a 50-megawatt (MW) coal-fired unit. Condition 26 of that Permit to Operate required GVEA to develop a Visibility Moni toring Plan and operate visibility monitoring equipment for the period prior to the initial st artup of the HCCP through the completion of 1 full year of commercial operation of HCCP . The Visibility Monitoring Plan was public noticed and submitted to EPA, ADEC and the NP S for approval. The objectives of the HCCP post-construction Visibility Monitoring Prog ram were to collect sufficient visual and measurement data to:

1. Provide reasonable assurance that nitrogen oxides (NO x ), sulfur dioxide (SO 2 ), and particle emissions from the HCCP and Healy Unit 1 sources (“Healy Power Plant”) were not adversely impairing visibility with in the Class I area of DNPP, and

2. Evaluate any trained National Park Servic e (NPS) observer’s reports of visibility impairment for their potential attribution to NO x , SO 2 , and particle emissions from operations of HCCP and Unit 1 . To meet the objectives of the Visibility Mo nitoring Program, photographic and /or air quality instrumentation was established at three monitoring stations. One station was established on a hill overlooking the plant to capture plant operations (Garner Hill); one was set up at the DNPP visitors center, and an ambi ent air monitoring station was set up at the Park Boundary between the two camera sites (B ison Gulch Monitoring Station)Photographic monitoring equipment recorded visibility and weather conditions using:

• Continuous time-lapse video from Garner Hill of the Healy Power PlantBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 1-2 • Continuous time-lapse video of the Nenana Valley north of the DNPP Visitor Access Center A comparison of the time variation of the SO 2 concentrations, as determined by ambient SO 2 monitoring, and light scattering by sulfate pa rticles determined source attribution of the sulfate. These data were used to estimate the contribution of the SO 2 emissions from the Healy Power Plant (Healy 1 and HCCP) to light scattering by particles within DNPP. Monitoring equipment at the Bison Gulch Moni toring Station continuously measured, with 5-minute resolution:

• Light scattering by fine particles using a he ated, gas-tight integrating nephelometer with a 2.5- μ m cutpoint cyclone

• Ambient air SO 2 concentrations

• Relative humidity

• Ambient temperature

• Wind speed and wind direction This Visibility Monitoring Program was initia ted when HCCP began its first year of the demonstration period, which was scheduled for January 1, 1998. Therefore, the monitoring program began immediately prior to that date (late December 1997). During the time period the visibility monitoring program was active , Healy 1 was operating with the current NO x control configuration, the current bag house, but the current SO 2 reduction system was not operating. Therefore, the visibility monitoring program was active at a time when both units were operating and Healy 1 was emitting more SO 2 than it does now. Additionally, HCCP had not been fully optimized resulting in em issions above normal operating conditions. The duration of the post-construction monito ring program was for an agreed upon 2 years (1 year of demonstration operation and 1 ye ar of commercial operation). The monitoring program ended during in 2000. Quarterly re ports were submitted to ADEC, EPA and the NPS. In 2000, the ADEC, EPA and NPS all agr eed the Visibility Monitoring Program could be temporarily shut down as HCCP never reac hed full commercial operation. HCCP has not operated since.During the 2-year time period no visibility impairment was observed by trained NPS observers while Healy 1 was operatin g at full load. This data demonstrate that actual visibility impairment at DNPP from He aly has not been detectable, even with both units operating. During the visibility monito ring program, there were occasions when a slight plume was visible and recorded by vi deo.. However, no correlation was reached between this slight plume and any visibility issues within DNPP. At the same time, a three year study in which pa rticles that cause or contribute to regional haze were measured and analyzed to determine if Healy was contributing to regional haze. The study was funded by GVEA, managed by the NPS, and conducted by Air Resource Specialists, Inc. and the University of Alas ka –Fairbanks. Results of t his study are summarized in a report entitled “Final Report on the Results from the Poker Flat, Denali National Park and Preserve, and Trapper Creek CASTNET Protocol Sites, July 1998 through June 2001 and was submitted to the agencies . The report concluded that there was no specific indication that operations form He aly Power Plant contribu ted to regional haze.AsBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 1-3 defined in the BART guidelines, there are five basic elements that are considered when evaluating BART. These are defined as:

1. The cost of the controls

2. The energy and non-air environmental impacts of compliance

3. Any existing pollution control technology in use at the source

4. The remaining useful life of the source

5. The degree of improvement in visibility whic h may reasonably be anticipated from the use of such technology This report documents the BART analysis that was performed on Healy 1 and Auxiliary Boiler #1 by CH2M HILL for GVEA. The analysis was performed for the pollutants: NO x , SO 2 , and particulate matter less than 10 microns in aerodynamic diameter (PM 10 ), because they are the primary criteria pollutants that affect visibility.GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 2-1 

# 2.0 Present Unit Operation

Healy 1 is a nominal 25-MW unit located in Healy, Alaska, approximately 8 kilometers (5 miles) from DNPP. The unit is a wall-fire d, dry-bottom boiler manufactured by Foster Wheeler. The BART presumptive NOx limit fo r dry-bottom wall-fired boilers burning subbituminous coal is 0.23 lb/MMBtu.

Low NO x burners (LNB) and over-fired air (OFA) po rts were installed in 1996. Particulate emissions are collected by a reverse gas baghouse installed in the early 1970s. Sulfur oxides are controlled by a dry sorbent injection syst em installed in 1999. At the present time sodium bicarbonate is the sorbent which is inje cted into the flue gas after the air heater. Auxiliary Boiler #1 is only used to supply he at to the Healy 1 building during shutdown periods or during emergency repa irs to Healy 1. Auxiliary Boiler #1 also provides steam for water processing and hot potable water to th e HCCP if called for during periods when Healy 1 is not operating. The unit is also fired monthly for maintenance checks. Healy 1 began operation in 1967. This analysis is based on the unit operating with a remaining useful life of 15 years. This report does not attempt to quantify any additional life extension costs needed to allow the unit and these control devices to operate beyond 15 years.

Table 2-1 lists additional unit information and study assumptions for this analysis. Coal characteristics are included in the table. The on ly source of coal burned at Healy 1 is the Usibelli Coal Mine (UCM). The coal from this mine is ranked as low-sulfur sub-bituminous.

TABLE 2-1 Present Unit Operation Healy 1

General Plant Data
Site Elevation Feet Above Mean Sea Level 1,260 Stack Height Feet 122

Stack Exit Internal Diameter Feet /Exit Area Sq. Ft. 4.83/18.31
Stack Exit Temperature °F 320 Stack Exit Velocity Ft/Sec 136.51
Stack Flow Actual Cubic Feet per Minute (acfm) 150,000 Annual Unit Capacity Factor (%) 96 to 100
Net Unit Output (MW) 25.5/ 26.0 (Winter/Summer range)
Net Unit Heat Rate (Btu/kilowatt hour [kWh])(100% load) 13,500
Boiler Heat Input (MMBtu/Hr)(100% load) 340
Type of Boiler Wall-fired, dry bottomBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 2-2 TABLE 2-1 Present Unit Operation Healy 1

Boiler Fuel Coal with oil start-up Coal Source 1 UCM Coal Heating Value (Btu/lb) 6766
Coal Sulfur Content (wt. %) 0.17
Coal Ash Content (wt. %) 13.65
Coal Moisture Content (wt. %) 28.97 Coal Nitrogen Content (wt. %) 0.57

Current NO x Controls Low-NO xBurners and OFA

Current SO 2 Controls Dry sorbent injection (sodium bicarbonate)

Current PM 10 Controls Reverse-gas fabric filter

1 Coal information represents one sample from the UCM dated 2-07-07 and represents typical but not average coal burned at Healy.GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-1 

# 3.0 BART Engineering Analysis

3.1 Applicability
In compliance with regional haze requiremen ts, the State of Alaska must prepare and submit visibility State Implementation Plans (S IPs) to the EPA for Class I areas. The State has estimated that the formal submittal of the SIPs will occur by 2009. The first phase of the regional haze program is the implementation of BART emission controls on all BART eligible units, within 5 years after EPA approv al of the SIP. This BART analysis evaluates retrofit control options and discusses BART controls for Healy 1.


# 3.2 BART Process
The specific steps in a BART engineering analys is are identified in 40 CFR 51 Appendix Y, Section IV. The evaluation must include the following:

1. The identification of available, techni cally feasible, retrofit control options

2. Consideration of any pollution control equipment in use at the source (which affects the availability of options and their impacts)

3. The costs of compliance with the control options

4. The remaining useful life of the facility

5. The energy and non-air quality environmental impacts of compliance

6. The degree of visibility improvement which ma y reasonably be anticipated from the use of BART These steps are incorporated into the BART analysis as follows: Step 1 – Identify All Available Retrofit Control Technologies

• This engineering analysis evaluates control options, including existing controls and discusses control technologies for Healy 1. Step 2 – Eliminate Technically Infeasible Options
The identification of available, technica lly feasible, retrofit control options

• Space was not a consideration in determining feasibility

• Consideration of any pollution control equipment in use at the source (which affects the applicability of options and their impacts)BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-2 Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies Step 4 – Evaluate Impacts and Document the Results

• The costs of compliance with the control options

• The remaining useful life of the facility

• The energy and non-air quality environmental impacts of compliance Step 5 – Evaluate Visibility Impacts

• The degree of visibility improvement which ma y reasonably be anticipated from the use of BART Consideration was made of applicable emission s control equipment, the costs of compliance associated with the control options, and the energy and non-air quality environmental impacts of compliance using identified control technologies. In some cases, enhancing the performance of the existing control equipment was considered. All costs included in the BART analysis are in 2008 dollars (not escalated to 2014 BART implementation date).



## 3.2.1 BART NO x 

## Analysis The 1994 PSD permit that allowed construction of HCCP resulted in extensive discussions between GVEA and ADEC on the operations of Healy 1 with regard to NO x and CO emissions. ADEC requested that GVEA operat e Healy 1 with the goal of minimizing NO x and CO emissions. The plant has been operated with this dual goal ever since. The BART process is focused on reducing NO x , SO 2 , and PM 10 emissions but not CO. Therefore, any consideration of reducing NO x must accommodate the earlier direction from ADEC where an increase in CO is an undesirable impact.

NO x formation in coal-fired boilers is a complex process that is dependent on a number of variables, including operating conditions, eq uipment design, and coal characteristics.



### 3.2.1.1 Formation of NO x During coal combustion, NO x is formed in three different ways. The dominant source of NO x formation is the oxidation of fuel-bound nitrogen (fuel NO x ). During combustion, part of the fuel-bound nitrogen is released from th e coal with the volatile matter, and part is retained in the solid portion (char). The nitrog en chemically bound in the coal is partially oxidized to nitrogen oxides (nitric oxide [NO] and nitrogen dioxide [NO 2 ]) and partially reduced to molecular nitrogen (N 2 ). A smaller part of NO x formation is due to high temperature fixation of atmospheric nitrogen in the combustion air. A very small amount of NO x is called “prompt” NO x . Prompt NO x results from an interaction of hydrocarbon radicals, nitrogen, and oxygen. In a conventional pulverized coal burner, air is introduced with turbulence to promote good mixing of fuel and air, which provides stable combustion. However, not all of the oxygen in the air is used for combustion. Some of the ox ygen combines with the fuel nitrogen to form NO x .BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-3 Coal characteristics directly and significantly affect NO x emissions from coal combustion. Coal ranking is a means of classifying coals according to their degree of metamorphism in the natural series, from lignite to sub-bituminous to bituminous and on to anthracite. Lower rank coals, such as the sub-bituminous coals from the UCM, produce lower NO x emissions than higher rank bituminous co als, due to their higher re activity and lower nitrogen content. The fixed carbon to volatile matter ra tio (fuel ratio), coal oxygen content, and rank are good relative indices of the reactivity of a coal. Lower rank coals release more organically bound nitrogen earlier in the combustion process than do higher rank bituminous coals. When used with low NO x burners, sub-bituminous coals create a longer time for the kinetics to promote more stable molecular nitrogen, and hence result in lower NO x emissions. Coal quality characteristics also impact the de sign and operation of the boiler and associated auxiliary equipment. Minor changes in qua lity can sometimes be accommodated through operational adjustments or chang es to equipment. It is important to note, however, that consistent variations in quality or assump tions of “average” quality for performance projections can be problematic. This is pa rticularly troublesome when dealing with performance issues that are very sensitive to both coal quality and combustion conditions, such as NO x formation. There are some additional considerations that illustrate the complexity of achieving and maintaining low NO x emissions with pulverized coal on a consistent shorter term, such as a 30-day rollin g average basis. Coal from the UCM mine is classified as sub-bituminous, wi th low BTU content and high moisture and ash. Coal quality also can vary significantly, which ma y impact stable boiler operation.

Good combustion is based on the “three Ts”: time, temperature, and turbulence. These parameters, along with a “design” coal are ta ken into consideration when designing a boiler and associated firing equipment such as fans , burners, and pulverizers. If a performance requirement such as NO x emission limits is subsequently changed, conflicts with and between other performance issues can result. The BART analysis for NO x emissions from Healy 1 is further described in this section.



### 3.2.1.2 Step 1: Identify All Availabl e Retrofit Control Technologies The first step of the BART process is to evaluate NO x control technologies with practical potential for application to Healy 1, including those control technologies identified as Best Available Control Technology (BACT) or lowe st achievable emission rate (LAER) by permitting agencies across the United States . A broad range of information sources have been reviewed in an effort to identify potent ially applicable emission control technologies. NO x from Healy 1 emissions are currently controlled through the use of LNB and OFA. The following potential NO x control technology options were considered:

• Maintain current operation and utilize existing LNB with OFA

• Optimize existing LNB with OFA through the utilization of a boiler consultant

• Replace OFA with rotating opposed fire air (ROFA)

• Replace OFA with ROFA and RotomixBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-4 • Add selective non-catalytic reduction (SNCR) system to existing low NO x burners with OFA

• Add selective catalytic reduction (SCR) system to existing Low NO x burners with OFA



### 3.2.1.3 Step 2: Eliminate Technically Infeasible Options For Healy 1, technical feasibility was primarily determined by physical constraints, the current boiler configuration and size, and impact on boiler operation and efficiency. Healy 1 has a current NO x emission rate of 0.25 pound per million British thermal units (lb/MMBtu), which is slightly above the pr esumptive BART level of 0.23 lb/MMBtu. For this BART analysis, information pertaining to SNCR and SCR was based on CH2M HILL’s project information, and the co st estimate for SNCR was updated by Fuel Tech in July 2008. GVEA provided additional emissions data and cost estimate for boiler tuning. Also, CH2M HILL solicited a budgetary estimate from Mobotec for their ROFA Rotamix technologies. Table 3-1 summarizes the control technology opti ons evaluated in this BART analysis, along with projected NO x emission rates.

TABLE 3-1 NO x Control Technology Emission Rates Healy 1
Technology Projected Emission Rate (lb/MMBtu)
Maintain Current Operation 0.25 a
Optimize Existing LNB w/OFA 0.23 b
Replace OFA with ROFA 0.15

ROFA and Rotamix 0.11

LNB w/OFA & SNCR 0.19

LNB w/OFA & SCR 0.07

a – Based on emissions from a typical operating day in 2 008, and represents a realistic level estimate of future emissions when operating existing equipment. b – Presumptive limit for > 200 MW wall fired boilers burning sub-bituminous coal



### 3.2.1.4 Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies Preliminary vendor proposals, such as those us ed to support portions of this BART analysis, may be technically feasible and provide expect ed emission rates; however, they include inherent uncertainties. These proposals are usua lly prepared in a limited time frame, may be based on incomplete information, may contai n over-optimistic conclusions, and are nonbinding. Therefore, emission rate values obta ined in such preliminary proposals must be qualified, and it must be recognized that co ntractual guarantees are established only after more detailed analysis has been completed. Th e following subsections describe the control technologies and the control effectiven ess evaluated in this BART analysis.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-5 

### Maintain Current Operation. This option would maintain the current operation of LNB and OFA. Expected future NOx emissions are es timated at 0.25 lb/MMBtu, and were derived from typical past actual emission rates in 2008. Utilizing committed or currently installed tech nology is consistent with BART analysis approaches CH2M HILL has used in prev ious BART analyses. For those cases when committed or existing technology and correspon ding emission rates are consistent with other BART control options, evaluation of curr ently installed emissions control equipment is warranted. 

### Optimizing Existing LNB/OFA System. The mechanism used to lower NOx with low NOx burners is to stage the combustion process and provide a fuel-rich condition initially; this is so oxygen needed for combustion is not divert ed to combine with nitrogen and form NOx. Fuel-rich conditions favor the co nversion of fuel nitrogen to N2 instead of NOx. Additional air (or OFA) is then introduced downstream in a lower temperature zone to burn out the char. Healy 1 currently has an LNB/OFA system wh ich was installed in 1996 to facilitate construction of HCCP. This system has been operating for an extended period of time, and plant personnel have exerted considerable effo rt to optimize performance (minimize CO within the existing permit NOx limits); it has not been optimized with the goal of minimizing NO x emissions. Optimization of the LNB/OFA system could be attempted by utilizing a boiler consultant with the intent of reaching a guideline (presumptive limit for 200MW unit) NO x target emissions of 0.23 lb/MMBtu. While th is may or may not be achievable, NO x emissions minimization will likely also impact other bo iler operating parameters such as loss on ignition (LOI), carbon monoxide (CO), and exce ss air. Therefore, the impact on all emissions must be considered when attempting to reduce NO x . 

### ROFA. Mobotec markets ROFA as an improved second generation OFA system. Mobotec states that the flue gas volume of the furnace is set in rotation by asymmetrically placed air nozzles. Rotation is reported to prevent lami nar flow, so that the entire volume of the furnace can be used more effectively for the combustion process. In addition, the swirling action reduces the maximum temp erature of the flames and increases heat absorption. The combustion air is also mixed more effectivel y. A typical ROFA installation would have a booster fan(s) to supply the high-velocity air to the ROFA boxes, and Mobotec would propose one 200 horsepower (hp) fan for Healy 1. Mobotec expects to achieve a NO x emission rate of 0.15 lb/MMBtu using ROFA technology. Results of computational fluid dynamics mode ling will determine the quantity and location of new ROFA ports, as well as the determining the need for modification or replacement of the existing burners.


### ROFA with Rotomix. The Rotamix system has been developed to optimize the reduction of unwanted substances, such as NOx. To opti mize NOx reduction, an amine-based reagent such as ammonia is added. The ammonia is added using lances that are inserted in the ROFA/Rotomix nozzles. The high-velocity air in the ROFA system carries the chemicals into the center of the furnace. Mobotec mark ets ROFA as an improved second generationBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-6 OFA system. Mobotec expects to achieve a NO x emission rate of 0.11 lb/MMBtu using ROFA/ Rotomix technology.


### SNCR. Selective non-catalytic reduction is gene rally utilized to achieve modest NOx reductions on smaller units. With SNCR, an amine-based reagent such as ammonia – or more commonly urea – is injected into th e furnace within a temperature range of 1,600 degrees Fahrenheit (°F) to 2,100°F, wh ere it reduces NOx to nitrogen and water. NOx reductions of up to 60 percent have been achieved, although 20 to 40 percent is more realistic for most applications. Reagent utilization, which is a measure of the efficiency with which the reagent reduces NO x , can range from 20 to 60 percent, depending on the amount of reduction, unit size, operating conditions, and allowable ammonia slip. With low reagent utilization, low temperatures, or inadequate mixing, ammonia slip occurs, allowing unreacted ammonia to create problems downstream. The ammonia may re nder fly ash unsaleable, react with sulfur to foul heat exchange surfaces, and/or create a visible stack plume. Reagent utilization can have a significant impact on economics, with higher levels of NO x reduction generally resulting in lower reagent utilization and higher operating cost. At Healy 1, a reduction of 25 percent in current NO x emissions for the addition of SNCR results in a projected emission ra te of 0.19 lb/MMBtu for SNCR.


### SCR. SCR works on the same principle as SNCR, but a catalyst is used to promote the reaction. Ammonia is injected into the flue-g as stream, where it reduces NOx to nitrogen and water. Unlike the high temperatures requir ed for SNCR, the reaction takes place on the surface of a vanadium/titanium-based catalyst at a temperature range between 580°F to 750°F. Due to the catalyst, the SCR process is more efficient than SNCR. The most common type of SCR is the high-dust configuration, wh ere the catalyst is located upstream of the airheater and downstream from the economizer. The design basis for Healy 1 results in a projected NO x emission rate of 0.07 lb/MMBtu. All of the control technologies described above are feasible for Healy 1, with the exception of consideration of potential space limitations.


### Level of Confidence for Vendor Post-Control Emissions Estimates. In order to determine the level of NOx emissions needed to achieve comp liance consistently with an established goal, NOx emissions from coal-fired generating units have been previously reviewed. As a result of this review, it was noted that NOx emissi ons can vary significantly around an average emissions level. Variations may result for many reasons, including coal characteristics, unit load, boiler operation including excess air, boile r slagging, burner equipment condition, coal mill fineness, and so forth. Recommended steps utilized for determining a le vel of confidence for the vendor expected values are as follows:

1. Establish expected NO x emissions value from vendor.

2. Evaluate vendor experience and historic al basis for meeting expected values.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-7 3. Review and evaluate unit physical and oper ational characteristics and restrictions. The fewer variations there are in operations, coal supply, etc., the more predictable and less variant the NO x emissions are.

4. For each technology expected value, there is a corresponding potential for actual NO x emissions to vary from this expected valu e. From the vendor information presented, along with anticipated unit operational data, an adjustment to the expected value can be made.
Therefore, vendor emission estimates should not be considered as absolute values for purposes of establishing permit limits for Healy 1.



### 3.2.1.5 Step 4: Evaluate Impacts and Document the Results This step involves the consideration of en ergy, environmental, and economic impacts associated with each control technology. The remaining useful life of the plant is also considered during the evaluation. 

### Energy Impacts. Optimization of the existing LNB with OFA is not expected to impact the boiler efficiency or draft fan power usage signif icantly. Therefore, this modification should not have significant energy impacts. The Mobotec ROFA and ROFA/Rotomix systems require installation and operation of one 200 hp ROFA fan. An SCR retrofit impacts the existing flue ga s fan system, which can typically result in additional pressure drop of 6 to 8 inches H 2 O. There would also be additional pumping costs associated with both SCR and SNCR injection systems. 

### Environmental Impacts. Tuning of the LNB with OFA will likely also affect the level of unburned carbon in the ash (c ommonly referred to as LOI) and CO emissions. A Mobotec ROFA installation may also affect LOI le vels and CO emissions, which will impact combustion efficiency. In prev ious discussions with ADEC, GVEA has been requested to minimize CO emissions. When optimizing the current LNB and OFA system with a goal of minimizing NOx emissions, or with the installation of a Mo botec ROFA system, there will be emissions trade-offs between NOx, CO, LO I, as well as potential impacts to boiler efficiency. Rotamix, SNCR, and SCR installati ons will result in some level of ammonia emissions. Rotamix, SNCR, and SCR installa tions could also impact the salability and disposal of fly ash due to ammonia levels and could potentially create a visible stack plume, which may negate other visibility improvemen ts. Other environmental impacts involve the storage of ammonia (especially if anhydrous a mmonia is used) and the transportation of the ammonia to the power plant site. 

### Economic Impacts. Costs and schedules for SCR were developed using CH2M HILL’s internal proprietary database, and supplemen ted (as needed) by vendor-obtained price estimates. Budgetary cost information for SNCR was furnished to CH2M HILL by Fuel Tech, and costs for the ROFA and ROFA/Rotomix systems were obtained from Mobotec. A comparison of the technologies on the basis of costs, design control efficiencies, and tons of NO x removed is summarized in Table 3-2, and the first year control costs in Figure 3-1. The complete Economic A nalysis is contained in Appendix A.BART ANALYSIS FOR HEALY POWER PLANTGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC3-8TABLE 3-2NOxControl Cost ComparisonHealy 1FactorCurrentOperation withExisting LNBw/OFAOptimizingExisting LNBw/OFASNCR ROFA ROFA/Rotamix SCRMajor Materials Design Costs $0 $20,000.0 $1.1Million $4.6 Million $6.9 Million $3.8 MillionTotal Installed Capital Costs $0 $20,000.0 $2.5Million $4.6 Million $6.9 Million $8.8 MillionTotal First Year Fixed andVariable O&M Costs$0 - $0.1 Million $0.1 Million $0.3 Million $0.2 MillionTotal First Year AnnualizedCost$0 $2,336.6 $0.4 Million $0.7 Million $1.1 Million $1.3 MillionPower Consumption (MW) 0 - 0.02 0.15 0.26 0.11Annual Power Usage (MillionkW-Hr/Yr)0 - 0.2 1.3 2.3 0.9NOxDesign Control EfficiencyaN/A 8.0% 25.0%40.0% 58.0% 72.0%Tons NOxRemoved per Year 0 30 92 148 214 266First Year Average ControlCost ($/Ton of NOxRemoved)0 79 4,533 4,553 5,108 4,748Incremental Control Cost($/Ton of NOxRemoved)0 79 6,629 4,585 6,341 3,255Note: Current operation is shown as zero for comparison purposes only.a--Assuming current emissions as baselineBART ANALYSIS FOR HEALY POWER PLANTGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC3-9FIGURE 3-1First Year Control Cost for NOxAir Pollution Control OptionsHealy 101,0002,0003,0004,0005,0006,0007,000Maintain CurrentOperationOptimizing ExistingLNB w/OFASNCR ROFA ROFA/Rotamix SCRAir Pollution Control Option

Control Cost ($/Ton NOx Removed)First Year Average Control CostFirst Year Incremental Control CostBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-10 

### 3.2.1.6 Step 5: Evaluate Visibility Impacts Please see Section 4.0, BART Modeling Analysis.



## 3.2.2 BART SO 2 

## Analysis
SO 2 forms in the boiler during the combustion process and is primarily dependent on coal sulfur content. The BART analysis for SO 2 emissions on Healy 1 is described below.



### 3.2.2.1 Step 1: Identify All Availabl e Retrofit Control Technologies A broad range of information sources was revi ewed in an effort to identify potentially applicable emission control technologies for SO 2 at Healy 1; this included control technologies identified as BACT or LAER by permitting agencies across the United States. The following potential SO 2 control technology options were considered:

• Maintain current operation and utilize existi ng sodium bicarbonate injection system

• Increase sodium bicarbonate injection rate to improve SO 2 removal utilizing the existing sorbent injection system

• Install lime spray dryer FGD system

• Install wet limestone FGD system



### 3.2.2.2 Step 2: Eliminate Technically Infeasible Options Maintain Current Operation. This option would maintain the current operation of the dry sorbent injection system. Expected future SO2 em issions are derived from typical past actual emission rates in 2008. Utilizing committed or currently installed tech nology is consistent with BART analysis approaches CH2M HILL has used in prev ious BART analyses. For those cases when committed or existing technology and correspon ding emission rates are consistent with other BART control options, evaluation of curr ently installed emissions control equipment is warranted. 

### Increase Sodium Bicarbonate Injection Rate. Healy 1 currently operates a dry sorbent injection system which injects sorbent into the flue gas after the air heater and upstream of the baghouse or fabric filter to control SO 2 emissions. Since the system was installed in 1999, GVEA has used three different materials as sorbent in an attempt to maximize the efficiency of the system. When the system was first installed, calcium carbonate was used as the sorbent. Several years later GVEA be gan experimenting with trona (a sodium sesquicarbonate) and was able to increase SO 2 capture significantly. In 2007, GVEA was able to optimize the system even furthe r by using sodium bicarbonate The SO 2 in the flue gas reacts with the sodium bicarbonate to form dr y particles, which are captured downstream in the existing fabric filter. Under current op eration, the dry sodium bicarbonate system consistently achieves approximately 50 percent removal of SO 2 (percent removals listed in the SO 2 BART analysis section will be calculated from an uncontrolled emission levels unless specifically noted otherwise). An incr ease in the amount of sodium bicarbonate injected may have the potential to achieve SO 2 removal of up to 70 percent.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-11 However, there are several significant potent ial issues that must be addressed with increasing sodium bicarbonate injection with the existing dry sorbent injection system. All potential impacts must be considered when co nsidering increasing the sodium bicarbonate injection rate:

• The existing sorbent injection system design and equipment may not be able to support the required sodium bicarbonate feed rate to remove SO 2 continuously at 70 percent removal. While it may be possible to achieve 70 percent removal on a short-term basis, it is not feasible to operate the existing equi pment at that rate continuously with no interruptions.

• From operational experience on other sim ilar dry sodium injection systems, a brown NO 2 plume may be visible at higher SO 2 removal rates. It is uncertain whether a brown plume would be visible at a 70 percent removal rate.

• From previous testing at Healy 1 in Marc h 2008, higher sodium bicarbonate injection rates corresponded with higher mercury emissions. While it may be possible to operate the current SO 2 FGD system up to a 70 percent removal capability for some periods of time, consistently achieving this removal rate is not feasible when taking into account equipment capacities, SO 2 removal performance, and other environmental impacts. While a new dry sodi um bicarbonate injection system may be designed and installed with adequate capa city, concerns with the brown plume and potential higher mercury emission issues wo uld remain. Therefore, increasing the dry sodium bicarbonate injection rate may be able to improve the SO 2 reduction from the current 50 percent removal to a maximum of 70 percent.

While the current sodium bicarbonate feed ra te is approximately 370 lb/hr, the required feed rate to achieve a continuous 70 percen t reduction is uncertain. Although current information is limited regarding the required so dium bicarbonate injection rate required to achieve up to an overall 70 percent reductio n, for purposes of this BART analysis, an estimated feed rate of 700 lb/hr up to 1400 lb/hr is estimated. This would result in an additional $0.5 to $1.0 million in additi onal annual sorbent co st, and an estimated $750,000 was assumed for economic evaluation purposes. Sorbent injection rates also vary according to coal sulfur levels. 

### New Lime Spray Dryer FGD System. The lime spray dryer typically injects lime slurry in the top of the absorber vessel with a rapidly rota ting atomizer wheel. The rapid speed of the atomizer wheel causes the lime slurry to separate into very fine droplets that intermix with the flue gas. The SO 2 in the flue gas reacts with the calcium in the lime slurry to form dry calcium sulfate particles. At Healy 1, this dry particulate matter would be captured downstream in the existing baghouse, along with the fly ash. It is assumed that a lime spray dryer system will produce a dry waste pr oduct suitable for landfill disposal. The lime spray dryer FGD system with the ex isting baghouse is projected to achieve up to 75 percent SO 2 removal at Healy 1. This would result in an estimated controlled SO 2 emission rate of 0.15 lb/MMBtu, based on an uncontrolled SO 2 emission rate of 0.60 lb/MMBtu.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-12 Operation of a lime spray dryer FGD system wo uld result in a wet plume, reduced plume rise, and the potential for higher near field air quality impacts. 

### New Wet Limestone FGD System. Wet limestone FGD systems operate by treating the flue gas in large scrubber vessels with a limestone solution. Wet FGD scru bbers use an absorber tower in which flue gas is contacted by the limestone slurry, resulting in conversion of SO 2 , in the flue gas into calcium sulfat e (gypsum), with carbon dioxide (CO 2 ) going up the stack. The calcium sulfate is removed from the scrubber and disposed, and it is assumed that the waste product from a wet limestone scru bber system is suitable for landfill disposal. Installation of a wet limestone FGD system at Healy 1 is estimated to achieve approximately 88 percent SO 2 removal which equates to an SO 2 outlet emission rate of 0.07 lb/MMBtu. Operation of a wet limestone FGD system would result in a wet plume, reduced plume rise, and the potential for higher near field air quality impacts. All of the control technologies described above are feasible for Healy 1, with the exception of consideration of potential space limitations.



### 3.2.2.3 Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies Healy 1 currently has an uncontrolled SO 2 emission rate of approximately 0.60 lb/MMBtu and a controlled SO 2 emission rate of 0.30 lb/MMBtu, which equates to a removal performance of approximately 50 percent. Tabl e 3-3 presents the control technologies being evaluated and the expected removal efficiencies and emission rates.

TABLE 3-3 Summary of SO 2 Control Effectiveness Healy 1

Control Technology Removal Efficiency (Current Emission Baseline/Uncontrolled Emission Baseline) Projected Emission Rate (lb/MMBtu)
Maintain Current operation NA/50% 0.30 a

Increase sodium bicarbonate feed rate utilizing existing dry sorbent injection system Up to 40%/Up to 70% 0.18

Lime spray dryer 50%/75% 0.15

Wet limestone 77%/88% 0.07

a -- Based on emissions from a typical operating day in 2 008, and represents a realistic level estimate of future emissions when operating existing equipment



### 3.2.2.4 Step 4: Evaluate Impacts and Document the Results This step involves the consideration of en ergy, environmental, and economic impacts associated with each control technology. The remaining useful life of the plant is also considered during the evaluation.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-13 

### Energy Impacts. The installation of a new lime spray dryer or wet limestone FGD system would require approximately 240 kilowatts (k W) of additional power. Upgrading the existing dry sorbent injection system would require approximately 20 kW of additional power. 

### Environmental Impacts. Based on recent stack testing, up grading the existing dry sorbent sodium bicarbonate FGD system from 50 percen t to up to 70 percent removal performance will result in an increase in mercury emi ssions and may result in a brown plume. Installation of a new lime spray dryer or wet lim estone FGD system will result in the storage of new chemicals onsite and a new waste stream for the facility. The exit flue gas stack temperature with both of these technologies will be less than the current operation, thus flue gas buoyancy will be decreased (see Section 5). In addition, saturated flue gas would significantly increase the probability of crea ting fog during the summer and ice fog during the winter, in the area surrounding the plant. 

### Economic Impacts. A summary of the costs and amount of SO 2 removed for the control technologies discussed above is provided in Ta ble 3-4, and a comparison of the first-year control cost ($/ton removed) is shown in Fi gure 3-2. The complete economic analysis is contained in Appendix A.BART ANALYSIS FOR HEALY POWER PLANTGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC3-14TABLE 3-4SO2Control CostHealy 1FactorMaintain CurrentOperation with ExistingDry Sorbent InjectionOptimizing ExistingDry Sorbent InjectionDry FGD Wet Limestone FGDMajor Materials Design Costs 0 $0.0 Million $3.6 Million $6.4 MillionTotal Installed Capital Costs 0 $0.0 Million $8.4 Million $15.0 MillionTotal First Year Fixed and Variable Operations andMaintenance Costs0 $0.8 Million $0.6 Million $0.8 MillionTotal First Year Annualized Cost 0$0.8 Million $1.5 Million $2.6 MillionPower Consumption (MW) 0 0.02 0.24 0.24Annual Power Usage (kW-Hr/Yr) 0 0.2 2.1 2.1SO2Design Control EfficiencyaN/A Up to 40.0% 50.0% 76.7%Tons SO2Removed per Year 0 177 222 340First Year Average Control Cost ($/Ton of SO2Removed)0 4,275 4,255 7,661Incremental Control Cost ($/Ton of SO2Removed) 0 4,275 17,516 9,044a--Assuming current emissions as baselineBART ANALYSIS FOR HEALY POWER PLANTGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC3-15FIGURE 3-2First Year Control Cost for SO2Air Pollution Control OptionsHealy 102,0004,0006,0008,00010,00012,00014,00016,00018,00020,000Maintain Current Operation Optimizing Existing Dry SorbentInjectionDry FGD Wet Limestone FGDAir Pollution Control Option

Control Cost ($/Ton SO2 Removed)First Year Average Control Cost ($/Ton SO2 Rem.)First Year Incremental CostBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-15 

### 3.2.2.5 Step 5: Evaluate Visibility Impacts Please see Section 4.0, BART Modeling Analysis.



## 3.2.3 BART PM 10



## Analysis Maintain Current Operation. This option would maintain the current operation of the baghouse. Expected future NO x emissions are estimated at 0.015 lb/MMBtu, which is consistent with expected emissions from a baghouse. It is assumed that the Healy Unit 1 baghouses is either achieving, or is capable of achieving, the 0.015 lb/MMBtu emission value. Utilizing committed or currently installed tech nology is consistent with BART analysis approaches CH2M HILL has used in prev ious BART analyses. For those cases when committed or existing technology and correspon ding emission rates are consistent with other BART control options, evaluation of curr ently installed emissions control equipment is warranted. Healy 1 currently has a reverse gas baghouse inst alled for particulate control. This baghouse has 12 compartments, each with 64 bags approximately 33 feet in length and 11.5 inches in diameter. The design air to cloth ratio is approx imately 2.0 with all compartments in service. A baghouse is a state-of-the-art technology for PM 10 control for Healy 1. Other control technologies such as a mechanical collector, hot or cold electrostatic precipitators, or wet particulate scrubbers could be cons idered as additional feasible PM 10 control options. However, none of these alternative technologi es are considered to have the potential of matching the consistent PM 10 removal performance of a baghouse. Therefore, the existing baghouse is considered BART for Healy 1, and completion of the five-step BART process is not required.GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-1 

# 4.0 BART Modeling Analysis

4.1 Model Selection

CH2M HILL used a Gaussian puff dispersion modeling syst em, Gaussian puff dispersion model (CALPUFF), to assess the visibility impact s of emissions from the BART sources at the GVEA Healy Power Plant at DNPP. The CALPUFF modeling system includes the Me teorological data preprocessing program for CALPUFF (CALMET) meteorological mode l CALPUFF with algorithms for chemical transformation and deposition, and a post proc essor capable of calculating concentrations, visibility impacts, and deposition (CALPOST ). The CALPUFF modeling system was applied in a full, refined mode. Version numbers of the various programs in the CALPUFF system used by CH2M HILL were as follows:

• CALMET Version 6.211, Level 060414

• CALPUFF Version 6.112, Level 060412

• CALPOST Version 6.131, Level 060410


# 4.2 CALMET Methodology

4.2.1 Dimensions of the Modeling Domain CH2M HILL used the CALMET model to genera te a three-dimensional wind field and other meteorological parameters suitable for us e by the CALPUFF model. A modeling domain was established to encompass the GVEA Healy Power Plant and allow for a 50-kilometer (km) buffer around DNPP. The modeling grid extends 550 kilometers in the east-west direction by 650 kilometers in the north-south direction which includes a 50 kilometer buffer around DNPP. Grid resolution is 2 km. Figure 4-1 shows the extent of the modeling domain. CH2M HILL followed the methodology outlined in the Western Regional Air Partnership (WRAP) CALMET/CALPUFF Protocol for BA RT Exemption Screening Analysis for Class I Areas in Western United States (WRAP Protocol) (2006). The Mesoscale Meteorological Model, Version 5 (MM5) files us ed as input to CALMET were provided on the WRAP Website. http://pah.cert.ucr.edu/aqm/308/bart /WRAP_RMC_BART_Protocol_Aug15_2006.pdf

CH2M HILL used the Lambert Conformal Conic map projection for the analysis due to the large extent of the domain.BART ANALYSIS FOR HEALY POWER PLANTGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC4-2FIGURE 4-1Healy BART Modeling DomainGVEA Healy Power Plant-50050100150200250300350400450500550600650700-250 -150 -50 50 150 250 350 450X (km)

Y (km)Denali ReceptorsHealyOriginBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC The default technical options listed in the WRAP Protocol current example CALMET.inp file were used for CALMET. Vertical resolution of the wind field included 11 layers, with vertical face heights as follows (in meters):

• 0, 20, 100, 200, 350, 500, 750, 1000, 2000, 3000, 4000, 5000 Other user-specified model options were set to values established by WRAP Regional Modeling Center (RMC) BART Protocol. Table 4- 1 lists the key user-specified options used for this analysis.

TABLE 4-1 User-Specified CALMET Options GVEA Healy Power Plant

CALMET Input Parameter Value
CALMET Input Group 2 Map Projection (PMAP) Lambert Conformal Longitude Origin -151 degrees Latitude Origin 59 degrees

1 st Standard Parallel 30 degrees

2 nd Standard Parallel 60 degrees X-Origin Offset -200 km Y-Origin Offset 0 km Grid Spacing (DGRIDKM) 2

Number of Grids 275 x 325

Domain Extent 550 km x 650 km Number Vertical Layers (NZ) 11
Top of Lowest Layer (m) 20 Top of Highest Layer (m) 5000
CALMET Input Group 4
Observation Mode (NOOBS) 1
CALMET Input Group 5 Prog. Wind Data (IPROG) 14
(RMAX1) 50
(RMAX2) 100
Terrain Influence (TERRAD) 10
(R1) 100
(R2) 200
CALMET Input Group 6 Max Mixing ht (ZIMAX) 4500BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-4 

### 4.2.1.1 CALMET Input Data The CALMET model was run for 2002 only as recommended in the WRAP protocol for Alaska. CALMET inputs and scripts were obtained from the State and were used to recreate CALMET output. CALMET was run using th e 15-km resolution 2002 MM5 data, surface meteorological observations fr om five sites and terrain and land use data. Table 4-2 lists the surface meteorological si tes. Precipitation data were based on MM5 15-km output. MM5 precipitation was used instead of observed precipitation.

TABLE 4-2 CALMET Surface Stations GVEA Healy Power Plant

Site ID LCC-X (km) LCC-Y (km)

EDF (Elmendorf/Anchorage) 26401 64.614 250.825

PANC (Anchorage International Airport) 26451 53.916 245.081

VWS (Valdez/WSO) 26442 251.006 244.575
ENA (Kenai Municipal Airport) 26523 -12.782 175.868

HOM (Homer Airport) 25507 -27.103 72.100



# 4.3 CALPUFF Modeling Approach
Methodologies for the BART control techno logy visibility improvement modeling were defined in the WRAP protocol. CALPUFF was run with the meteorological output from CALMET over the modeling domain described earlier. The CALPUFF model was used to predict visibility impacts for the baseline scenar io for comparison to the predicted impacts for individual control options for GVEA Healy Power Plant.



## 4.3.1 Background Ozone and Ammonia Hourly values of background ozone concen trations were used by CALPUFF for the calculation of SO 2 and NO x transformation with the MESOPUFF II chemical transformation scheme. CH2M HILL obtained hourly ozone data for DNPP, Alaska, located within the modeling domain for 2002. For periods of missing hourly ozone data, th e chemical transformation relied on a monthly default value of 40 parts per billion. Backgrou nd ammonia was set to 0.1 parts per billion. Both of these background values we re taken from the WRAP Protocol.



## 4.3.2 Stack Parameters The stack parameters used for the baseline mode ling reflect those that are in place under the current permit for GVEA Healy Power Plant. Indi vidual control stack parameters reflect the anticipated changes associated with installation of the control technology alternatives that are being evaluated.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-5 

## 4.3.3 Emission Rates Modeling baseline emission rates for GVEA Heal y Power Plant reflect peak 24-hour average emissions from the previous 12 month period , which may occur albeit rarely, under the source’s current permit with existing cont rols. Baseline emissions utilized for economic analyses represent a realistic depiction of ant icipated annual emissions for the unit.

CH2M HILL used available continuous emi ssion monitoring data to determine the 24-hour average actual emission rates. NO x and SO 2 emissions were based on Continuous Emission Monitor (CEM) data fr om the highest emitting day in the one year period from May 1, 2007 to April 30, 2008. Emissions were modeled for SO 2 and NO x . The model was run to include chemical transformation and calculated concentrations of nitric acid, nitrates, and sulfates.

Individual control emission rates reflect the effects of the emissions control options under consideration. Modeled pollutants were the same as those listed for the pre-control scenario.



## 4.3.4 Individual Control Scenarios Nine total individual control technologies for NO x and SO 2 were evaluated. The selection of each control device was made based on the engineering analyses performed in Section 3.

• NO x Option 0:Maintain Current Operation

• NO x Option 1 :Optimize Existing Low NO x Burners with OFA

• NO x Option 2: Replace OFA with ROFA

• NO x Option 3: Replace OFA with ROFA and Rotomix

• NO x Option 4: Low NO x Burner with OFA and SNCR System

• NO x Option 5: Low NO x Burner with OFA and SCR System

• SO 2 Option 0:Maintain Current Operation

• SO x Option 1: Increase Sodium Bicarbonate Feed Rate

• SO x Option 2: Install Lime Spray Dryer FGD System

• SO x Option 3: Install Wet Limestone FGD System Table 4-3 and Table 4-4 presents the stack para meters and emission rates used for the GVEA Healy Power Plant analysis for baseline and indi vidual control modeling. Table 4-5 presents the stack parameters and emission rates for Auxiliary Boiler #1. In accordance with the WRAP Protocol, elemental carbon stack emissi ons and organic aerosol emissions were not modeled.BART ANALYSIS FOR HEALY POWER PLANTGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC4-6TABLE 4-3BART Model Input DataGVEA Healy Power PlantBaseline NOX0 NOx1 NOx2 NOx3 NOx4 NOx5 SOX0 SOX1 SOX2 SOX3Highest24 houraveragepeakMaintainExistingLow NOxBurnerswith OverFire Air(OFA)OptimizeExistingLow NOxBurnerswith OverFire Air(OFA)Replace OFAwith RotatingOpposed FireAir (ROFA)ReplaceOFA withROFA andRotomixLow NOxBurner withOFA andSelectiveNon-CatalyticReduction(SNCR)SystemLow NOxBurner withOFA andSelectiveCatalyticReduction(SCR) SystemExisting DrySodiumBicarbonateFlue GasDesulfurization(FGD) System(increase feedrate)Upgrade DrySodiumBicarbonateFlue GasDesulfurization(FGD) System(increase feedrate)InstallLimeSprayDryerFGDSystemInstall WetLimestoneFGDsystemSO2StackEmissions(lb/hr)182.2 182.2 182.2 182.2 182.2 182.2 182.2 102.0 60.8 51.0 24.0NOxStackEmissions(lb/hr)151.0 85.0 77.7 50.7 35.5 63.0 24.0 151.0 151.0 151.0 151.0BART ANALYSIS FOR HEALY POWER PLANTGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC4-7TABLE 4-4Stack Parameters and Emission Rates Healy Unit1Stack Parameters Unit 1aBaseline, All NOx, SOx0 and SOx1 SOx2 SOx3Stack Height (feet)122.0 122.0 122.0Stack Height (meters)37.2 37.2 37.2Base Elevation (meters)384.0 384.0 384.0Base Elevation (feet)1260 1260 1260Stack Exit Diameter (feet)4.8 4.8 4.8Stack Exit Diameter (meters)1.5 1.5 1.5Stack Exit Temperature (degF)320170136Stack Exit Temperature (K)433.2 349.8 330.9Stack Exit Flow (acfm)150,000 121,154 114,615Stack Exit Area (square feet)18.3 18.3 18.3Stack Exit Velocity (feet per second)136.5 110.3 104.3Stack Exit Velocity (meters persecond)41.6 33.6 31.8aUnit 1 parameters derived from source tests and manufacturers dataBART ANALYSIS FOR HEALY POWER PLANTGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC4-8TABLE 4-5Stack Parameters and Emission Rates Auxiliary Boiler #1Stack Parameters Auxiliary BoilerbAuxiliary BoilerStack Height (feet)85Stack Height (meters)25.9Base Elevation (meters)384.0Base Elevation (feet)1260Stack Exit Diameter (feet)13.0Stack Exit Diameter (meters)3.96Stack Exit Temperature (degF)505Stack Exit Temperature (K)450Stack Exit Flow (acfm)159,310Stack Exit Area (square feet)132.7Stack Exit Velocity (feet per second)20.0Stack Exit Velocity (meters per second)6.1bAuxiliary Boiler parameters derived from WRAP Alaska BART analysisBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-9 

## 4.3.5 Modeling Process The CALPUFF modeling for the control technology options for GVEA Healy Power Plant followed this sequence:

• Model pre-control (baseline) emissions

• Model individual control scenario (if applicable)

• Determine degree of visibility improvement

• Model other control scenarios

• Determine degree of visibility improvement

• Factor visibility results into BART “five-step” evaluation



## 4.3.6 Receptor Grids Discrete receptors for the CALPUFF modeling were placed at uniform receptor spacing along the boundary and in the interior of each area of concern. DNPP Class I area receptors were taken from the NPS database for Class I area modeling receptors. The TRC COORDS program was used to convert all latitude/l ongitude coordinates to Lambert Conformal Conic coordinates, including receptors, meteor ological stations, and source locations.


# 4.4 CALPOST
The CALPOST processor was used to determin e 24-hour average visibility results with output specified in deciview (dV) units. Calcul ations of light extinction were made for each pollutant modeled. The sum of all extinction values was used to calculate the delta-dV ( ∆ dV) change relative to natural background. Default extinction coefficients for each pollutant, as shown below, were used.

• Ammonium sulfate 3.0

• Ammonium nitrate 3.0

• PM coarse (PM 10 ) 0.6

• PM fine (PM 2.5 ) 1.0

• Organic carbon 4.0

• Elemental carbon 10.0 CALPOST Visibility Method 6 was used to de termine the visibility impacts. Monthly relative humidity factors were used in the lig ht extinction calculations to account for the hygroscopic characteristics of nitrate and sulfate particles. The monthly relative humidity factors for DNPP as used by WRAP for Alaska are as follows:
2.5, 2.3, 2.1, 1.9, 1.9, 2.2, 2.5, 3.0, 2.8, 2.9, 3.0, 3.1 The natural background conditions as a reference for determining the ∆ dV change represented the 20 percent best natural visibi lity days. The change in visibility impairment for the BART modeling is based on the increase in Haze Index from a BART-eligible source or sources relative to natural background, de fined as the 20 percent best visibility days for each Class I area. This definition of natural ba ckground is consistent with the intent of the BART guideline (Federal Register Vol. 70, No. 128, pg 39125). Table 4-6 lists the annual average species concentrations from the WRAP protocol.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-10 TABLE 4-6 Average Natural Levels of Aerosol Components GVEA Healy Power Plant

Aerosol Component Average Natural Concentration (micrograms per cubic meter) for DNPP

Ammonium Sulfate 0.12

Ammonium Nitrate 0.10 Organic Carbon 0.47

Elemental Carbon 0.02

Soil 0.50

Coarse Mass 3.00
Note: Taken from WRAP RMC Alaska Modeling files



# 4.5 Presentation of Modeling Results
This section presents the results of the CA LPUFF visibility improvement modeling analysis for GVEA Healy Power Plant.



## 4.5.1 Degree of Visibility Change for Baseline vs. Preferred Scenario CH2M HILL modeled the GVEA Healy Power Pl ant for the baseline and nine individual control scenarios. The individual control scenarios included emission rates for SO 2 and NO x, which may be possible if BART controls were optimized or installed on the GVEA Healy Power Plant. The visibility results for DNPP are presented in Table 4-7. In addition, results for Auxiliary Boiler #1 are also given in Table 4-8.BART ANALYSIS FOR HEALY POWER PLANTGOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC4-11TABLE 4-7Costs and Visibility Modeling Results for Baseline Vs. Individual Control ScenariosGVEA Healy 1Scenario First Year CostHighest Delta-Deciview(ΔdV) No. of Days Above 0.5 dV Cost per dV ReductionCost per Reduction in No.of Days Above 0.5 dVIncremental Cost per dVReductionIncremental Cost perReduction in No. of DaysAbove 0.5 dVBaselinea3.359 136NOx Option 0: Existing Low NOx Burners with OFA $0b2.828 97 $0 $0 $0 $0NOxOption 1 :Optimize Existing Low NOxBurners with OFA $2,337 2.799 93 $4,173 $54 $80,586 $584NOxOption 2: Replace OFA with ROFA $672,997 2.688 80 $1,002,976 $12,018 $6,041,982 $51,589NOxOption 3: Replace OFA with ROFA and Rotomix$1,094,835 2.623 69$1,487,548 $16,341$6,489,815 $38,349NOxOption 4: Low NOxBurner with OFA and SNCR system $418,810 2.739 85 $675,500 $8,212 $5,827,802 $52,059NOxOption 5: Low NOxBurner with OFA and SCR system $1,263,251 2.573 65 $1,607,190 $17,792 $5,086,994 $42,222SOx Option 0: Dry Sodium Bicarbonate FGD System $0b3.195 111 $0 $0 $0 $0SOXOption 1: Increase Dry Sodium Bicarbonate FGDSystem (increase feed rate)$758,322 3.109 97 $3,033,288$19,444 $8,817,698 $54,166SOXOption 2: Install Lime Spray Dryer FGD System $1,607,872 4.229 116 -$1,848,129$80,394 -$758,527 -$44,713SOXOption 3: Install Wet Limestone FGD System $2,659,104 4.519118 -$2,292,331 $147,728-$3,624,938 -$525,616aBaseline is defined as current operation values with the highest24-hr average for the modeling analysis and ($0) for the economic analysisbThere are no costs referenced for existing operations for economic purposes although in reality there are significant operationand maintenance costs associated with the current operations.TABLE 4-8Visibility Results for Auxiliary Boiler #1Scenario Pollutant Controlled 1stHigh delta Deciview 8thHigh delta Deciview# of day above 0.5 # of day above 1.0Baseline none 0.067 0.02 0 0GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-1 

# 5.0 Preliminary Assessment and Recommendations

As a result of the completed technical and ec onomic evaluations, and in consideration of potential environmental impacts from implem entation of potential controls, and the modeling analysis completed for Healy 1, as well as consideration of the existing information documenting no detectable visi bility impairment at DNPP from current operations, existing controls are considered BART. The evaluation of visibility improvements for all emission control scenarios discussed were analyzed, and the results are compared in th e sections below, utilizing a Least-Cost Envelope, as outlined in the draft EPA (1990) New Source Review Workshop Manual

. 

# 5.1 Least-Cost Envelope Analysis
The total annualized cost, cost per dV reductio n, and cost per reduction in number of days above 0.5 dV for the control options modeled in Section 4 to determine the visibility impact on the Class 1 area, DNPP, are listed in Table 5-1. A comparison of the incremental costs between relevant options is shown in Table 5-2. The total annualized cost versus number of days above 0.5 dV and the total annualized cost versus Δ dV reduction are shown in Figures 5-1 and 5-2 for the Class I area. All modeling results utilize a baseline determin ed by the highest 24 hour average emission rate over the previous 12-month period. Comparing the modeling results from the anticipated emissions rate with existing co ntrols versus the highest 24 hour average emission rate, there is a resultant visibi lity improvement demonstrated. Visibility improvement due to NO x is quantified as a 39 day reduction in average number of days above 0.5 dV, while the SO 2 improvement is a 25 day reduct ion in average number of days above 0.5 dV. Since there is no additional co st to continue current operation with the existing NO x and SO 2 controls, the “Option 0” scenarios shown in Table 5-1 below are listed
at zero cost.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-2 

## 5.1.1 Analysis Methodology Page B-41 of the New Source Review Manual , EPA states that “Incremental cost-effectiveness comparisons should focus on annualized cost and emission reduction differences between dominant alternatives. Dominant sets of control alternatives are determined by generating what is called the envelope of least-cost alte rnatives. This is a graphical plot of total annualized costs for a total emissions reductions for all control alternatives identified in the BART analysis...” An analysis of incremental cost effectivene ss has been conducted. This analysis was performed in the following way:

• First, the control option scenarios are expre ssed per day and per dV reduction, represent a comparison of the different control option s, and are summarized in Tables 5-1 and 5-2 for the Class I area. TABLE 5-1 Class I Area Summary of Control Performance GVEA Healy 1

Options a Highest dV Reduction Reduction in Average Number of Days Above 0.5 dV (Days) Total Annualized Cost ($million) Cost per dV Reduction ($million/dV

Reduced) Cost per Reduction in No. of Days Above 0.5 dV ($million/Day

Reduced)

NO X Option 0 :Existing Low NOx burners with over-fire air (OFA) b 0.531 39 $0 b $0 b $0 b

NO x Option 1 :Optimize Existing Low NO x Burners with OFA 0.560 43 $0.0023 $0.0042 $0.0001

NO x Option 2: Replace OFA with ROFA 0.671 56 $0.6730 $1.0030 $0.0120

NO x Option 3: Replace OFA with ROFA and Rotomix 0.736 67 $1.0948 $1.4875 $0.0163

NO x Option 4: Low NO x Burner with OFA and SNCR System 0.620 51 $0.4188 $0.6755 $0.0082

NO x Option 5: Low NO x Burner with OFA and SCR System 0.786 71 $1.2633 $1.6072 $0.0178

SO X Option 0: Existing dry sodium bicarbonate flue gas desulfurization (FGD) system b 0.164 25 $0 b $0 b $0 b

SO x Option 1: Upgrade Dry Sodium Bicarbonate FGD System (increase feed rate) 0.250 39 $0.7583 $3.0333 $0.0194

SO x Option 2: Install Lime Spray Dryer FGD System c -0.870 20 $1.6079 -$1.8481 $0.0804

SO x Option 3: Install Wet Limestone FGD System c -1.160 18 $2.6591 -$2.2923 $0.1477

a Baseline is defined as current operation values with the hi ghest 24-hr average for the modeling analysis and ($0) for the economic analysis. All options are compared to baseline.

b There are no costs referenced for existing operations for economic purposes although in reality there are significant operation and maintenance costs associated with the current operations.

c Visibility impacts are greater with th is option because of lower plume rise resulting from colder and wetter plumeBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-3 • Then the most reasonable smooth curve of leas t-cost control option scenarios is plotted for each analysis. Figures 5-1 and 5-2 pres ent the two analyses (cost per dV reduction and cost per reduction in number of days ab ove 0.5 dV) for the Class 1 area impacted by the operation of Healy 1. In Figures 5-1 and 5-2 control options for NO x are compared as a graph of total annualized cost versus number of days above 0.5 dV and delta deciview reduction. The EPA states that “In calculating incremental costs, the analysis should only be conducted for control options that are dominant among all possible options.” In Figure 5-1, the dominant control options include Option 0 (Existing LNB and OFA), Option 1 (Optimize LNB and OFA), and Option 4 (SNCR) as depicted on the least-cost envelope . All other options are to the left of the curve and therefore are inferior options. Remainin g options should not be considered in the derivation of incremental cost effectivene ss. SNCR has the potential of removing an incrementally small amount of additional NO x for a significantly higher cost. Option 5 (SCR) offers the greatest potential for visibility impr ovement, however the high first year cost of over $1.2 million would impact the ultimate cost of generation for Healy 1. Currently, the interior is in an energy crisis and the incr eased cost to GVEA membership would be significant. The least-cost envelope analysis was also completed for SO 2 emissions, with results shown on Figures 5-3 and 5-4. The dominant SO 2 control is the continuation of current operations of the existing sodium bicarbonate injection system. Also as shown in Table 5-2 below, the installation of a lime spray dryer or wet lim estone scrubber results in an increase in Δ dv impact due to a lower flue gas temperature wi th these technologies (less plume rise). Table 5-3 below provides a comparison of the tons of NO x and SO 2 removed versus total annual cost on a rounded basis.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-4

TABLE 5-2 Class I Area Incremental Data GVEA Healy 1

Options Compared a Incremental Reduction in Days Above 0.5 dV (Days) Incremental dV Reductions (dV) Incremental Cost Effectiveness ($/dV) Incremental Cost Effectiveness ($/Days)

NO X Option 0 :Existing Low NOx burners with over-fire air (OFA) b 39 0.531 $0 b $0 b

NO x Option 1 :Optimize Existing Low NO x Burners with OFA 43 0.560 $80,586 $584

NO x Option 2: Replace OFA with ROFA 56 0.671 $6,041,982 $51,589

NO x Option 3: Replace OFA with ROFA and Rotomix 67 0.736 $6,489,815 $38,349

NO x Option 4: Low NO x Burner with OFA and SNCR System 51 0.620 $5,827,802 $52,059

NO x Option 5: Low NO x Burner with OFA and SCR System 71 0.786 $5,086,994 $42,222

SO X Option 0: Existing dry sodium bicarbonate flue gas desulfurization (FGD) system b 25 0.164 $0 b $0 b

SO x Option 1: Upgrade Dry Sodium Bicarbonate FGD System (increase feed rate) 39 0.250 $8,817,698 $54,166

SO x Option 2: Install Lime Spray Dryer FGD System 20 -0.870 -$758,527 -$44,713

SO x Option 3: Install Wet Limestone FGD System 18 -1.160 -$3,624,938 -$525,616

a Baseline is defined as current operation values with the hi ghest 24-hr average for the modeling analysis and ($0) for the economic analysis. All options are compared to baseline.

b There are no costs referenced for existing operations for ec onomic purposes although in r eality there are significant operation and maintenance costs associated with the current operations.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-5 FIGURE 5-1 Least Cost Envelope Compared to Baseline GVEA Healy 1 NO x Options

$0.0000 $0.2000 $0.4000 $0.6000 $0.8000 $1.0000 $1.2000 $1.4000

0 10 20 30 40 50 60 70 80 Reduction in Days of Exceeding 0.5 dv (days)Total Annualized Cost (Mil $)

FIGURE 5-2 Least Cost Envelope Compared to Baseline GVEA Healy 1 NO x Options

$0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 Highest Delta-Deciview Reduction (dv)Total Annualized Cost (Mil $)BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-6 FIGURE 5-3 Least Cost Envelope Compared to Baseline GVEA Healy 1 SO 2 Options

$0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 $0.80

0 5 10 15 20 25 30 35 40 45 Reduction in Days of Exceeding 0.5 dv (days)Total Annualized Cost (Mil $)

FIGURE 5-4 Least Cost Envelope Compared to Baseline GVEA Healy 1 SO 2 Options

$0.00 $0.20 $0.40 $0.60 $0.80

0.00 0.05 0.10 0.15 0.20 0.25 0.30 Highest Delta-Deciview Reduction (dv)Total Annualized Cost (Mil $)BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-7 Figure 5-5 and Figure 5-6 below graphically de picts information from Table 5-3 above, and presents the annual tons of NO x and SO 2 removed versus the total annual cost. TABLE 5-3 Annual Cost and Tons Removed Based on Current Operating Values GVEA Healy 1

Options Total Annual Cost (Rounded) Tons Removed
NOx Option 0: Existing Low NOx Burners w/OFA a See Note a See Note a

NO xOption1 Optimize Existing Low NO xBurners w/ OFA $2,000 30

NO xOption 2: Replace OFA w/ ROFA $400,000 92

NO xOption 3: Replace OFA w/ ROFA & Rotomix $700,000 148

NO xOption 4: Low NO xBurner w/ OFA & SNCR System $1,100,000 214

NO xOption 5: Low NO xBurner w/ OFA & SCR System $1,300,000 266
SO2 Option 0: Dry Sodium Bicarbonate FGD System See Note a See Note a

SO 2 Option 1: Upgrade Dry Sodium Bicarbonate FGD System (increase feed rate) $800,000 177

SO 2 Option 2: Install Lime Spray Dryer FGD System $1,600,000 222

SO 2 Option 3: Install Wet Limest one FGD System $2,700,000 340

a There are no costs referenced for existing operations (Option 0) for economic purposes because all costs and evaluations are compared to Option 0. In reality there are significant operation and maintenance costs associated with the current operations.BART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-8 FIGURE 5-5 Additional Annual cost versus Additional T ons Removed Compared to Existing Operations GVEA Healy 1 NO x Options

0 200000 400000 600000 800000 1000000 1200000 1400000

0 50 100 150 200 250 300
Tons NOx RemovedTotal Annual Cost

FIGURE 5-6 Additional Annual cost versus Additional T ons Removed Compared to Existing Operations GVEA Healy 1 SO 2 Options

0 500000 1000000 1500000 2000000 2500000 3000000

0 50 100 150 200 250 300 350 400
Tons SO2 RemovedTotal Annual CostBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-9 

## 5.1.2 Analysis of Results Analysis of the results for the DNPP from the tables and figures above supports the conclusions stated below. While the greatest reduction in dV and number of days above 0.5 dV is achieved with NO x Option 5 (SCR) and SO 2 Option 1 (Upgrade dry sodium bicarbonate FGD system), these options are not the selected alternativ es. As discussed above in Section 5.1.1, utilizing the least-cost curve analyses incorporates economic considerations of all alternatives and results in the co nclusions presented below in Section 5.2.


# 5.2 BART Conclusions

5.2.1 NO x 

## Emission Control The optimization of existing LNB w/OFA through the utilization of a boiler consultant while shown to be the most effective of th e new control options evaluated will not have a measurable improvement to visibility in DNPP. Any increase in CO emissions would be an undesirable environmental effect of implementation of this option. Since there is only an estimated 0.03 dV impr ovement between Option 1 and Option 0, and this difference is non-perceivable by the hu man eye maintaining current operation of the existing NOx controls are considered to be BART for Healy 1.



## 5.2.2 SO 2 

## Emission Control Even though increasing the sodium bicarbonat e injection rate while utilizing the existing sorbent injection system was shown to be the most effective of the new control options evaluated, implementation will not have a meas urable improvement to visibility in DNPP. An increase in mercury emissions and possi ble occurrence of a brown cloud would be undesirable environmental effects of implementation of this option. Since there is only an estimated 0.09 dV impr ovement between Option 1 and Option 0, and this difference is non-perceivable by the huma n eye, maintaining current operation of the existing SO 2 controls are considered to be BART for Healy 1



## 5.2.3 PM 10



## Emission Control The existing fabric filter is considered BART for Healy 1. 

## 5.2.4 Auxiliary Boiler # 1 Emissions and impacts from Au xiliary Boiler #1 are insignificant, and no controls are concluded as BART for this unit.


# 5.3 Just-Noticeable Differen ce in Atmospheric Haze

Conclusions reached in the reference document “Just-Noticeable Differences in Atmospheric Haze” by Dr. Ronald Henry state that only dV di fferences of approximately 1.5 to 2.0 dV or more are perceivable by the human eye. De ciview changes of less than 1.5 cannot be distinguished by the average person.. Therefor e, the modeling analysis results indicate that based on the above, no observable visibili ty improvements at DNPP would be expectedBART ANALYSIS FOR HEALY POWER PLANT

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-10 under any of the control options, since ma ximum modeled improvement for any control technology is only 0.5dV (for installation of SCR).


# 5.4 Recommendations

As summarized in the sections above, maintain ing operation of the existing controls are considered BART for Healy 1.

Because the NO x and SO 2 BART selections result in minimal visibility improvement, there will likely not be any perceptible difference (from just-noticeable-difference discussion above) in DNPP. Previous visibility studies hav e concluded that actual visibility impairment at DNPP from Healy has not been de tected by trained NPS observers.GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 6-1 

# 6.0 References

EPA. 1990. New Source Review Workshop Manual –P revention of Significant Deterioration Regional Haze Regulations and Guidelines for Best Available Retrofit Te chnology Determinations; Final Rule (40 CFR Part 51; July 6, 2005, pg 39129) Henry, Ronald C. 2002. “Just-Noticeable Differences in Atmospheric Haze.” Journal of the Air and Waste Management Association 52:1238-1243. October 2002
WRAP. 2006. Draft Final Modeling Protocol, CALMET/CA LPUFF Protocol for BART Exemption Screening Analysis for Class I Areas in the Western United States. Air Quality Modeling Forum. Regional Modeling Center. August 15, 2006.